Purification works for thermal power plant

ABSTRACT

A method for separation of CO 2  from the combustion gas from a thermal power plant fired with fossil fuel, wherein the combustion gas from the thermal power plant is used as cooled, compressed and reheated by combustion of natural gas in a combustion chamber to form an exhaust gas, where the exhaust gas is cooled an brought in contact with an absorbent absorbing CO 2  from the exhaust gas to form a low CO 2  stream and an absorbent with absorbed CO 2 , and where the low CO stream is heated by means of heat exchanges against the hot exhaust gas leaving the combustion chamber before it is expanded in turbines, is described. A plant for performing the method and a combined plant is also described.

The present invention relates to a method for separation of thecombustion gas from a thermal power plant fired by a fossil fuel into aCO₂ rich and a CO₂ poor stream, a separation plant for performing themethod and a combined plant comprising a thermal power plant fired by afossil fuel and the present separation plant.

The concentration of CO₂ in the atmosphere has increased by nearly 30%in the last 150 years. The concentration of methane has doubled and theconcentration of nitrogen oxides has increased by about 15%. This hasincreased the atmospheric greenhouse effect, something which hasresulted in:

-   -   The mean temperature near the earth's surface has increased by        about 0.5° C. over the last one hundred years, with an        accelerating trend in the last ten years.    -   Over the same period rainfall has increased by about 1%    -   The sea level has increased by 15 to 20 cm due to melting of        glaciers and because water expands when heated up.

Increasing discharges of greenhouse gases is expected to give continuedchanges in the climate. Temperature can increase by as much as 0.6 to2.5° C. over the coming 50 years. Within the scientific community, it isgenerally agreed that increasing use of fossil fuels, with exponentiallyincreasing discharges of CO₂, has altered the natural CO₂ balance innature and is therefore the direct reason for this development.

It is important that action is taken immediately to stabilize the CO₂content of the atmosphere. This can be achieved if CO₂ generated in athermal power plant is collected and deposited safely. It is assumedthat the collection represents three quarters of the total costs for thecontrol of CO₂ discharges to the atmosphere.

Thus, an energy efficient, cost efficient, robust and simple method forremoval of a substantial part of CO₂ from the discharge gas will bedesirable to ease this situation. It will be a great advantage if themethod can be realized in the near future without long-term research.

Discharge gas from thermal power plants typically contains 4 to 10% byvolume of CO₂, where the lowest values are typical for gas turbines,while the highest values are only reached in combustion chambers withcooling, for example, in production of steam.

There are three opportunities for stabilizing the CO₂ content in theatmosphere. In addition to the capturing of CO₂, non-polluting energysources such as biomass can be used, or very efficient power plants canbe developed. The capturing of CO₂ is the most cost efficient. Still,relatively little development work is carried out to capture CO₂, themethods presented up till now are characterized either by low efficiencyor by a need for much long-term and expensive development. All methodsfor capturing CO₂ comprise one or more of the following principles:

-   -   Absorption of CO₂. The exhaust gas from the combustion is        brought into contact with an amine solution, at near atmospheric        pressure. Some of the CO₂ is absorbed in the amine solution        which is then regenerated by heating. The main problem with this        technology is that one operates with a low partial pressure of        CO₂, typically 0.04 bar, in the gas which shall be cleaned. The        energy consumption becomes very high (about 3 times higher than        if it is cleaned with a CO₂ partial pressure of 15 bar). The        cleaning plant becomes expensive and the degree of cleaning and        size of the power plant are limiting factors. Therefore, the        development work is concentrated on increasing the partial        pressure of CO₂. An alternative is that the exhaust gas is        cooled down and re-circulated over the gas turbine. The effect        of this is very limited due to the properties of the turbine,        among other things. Another alternative is that the exhaust gas        which is to be cooled down, is compressed, cooled down again,        cleaned with, for example, an amine solution, heated up and        expanded in a secondary gas turbine which drives the secondary        compressor. In this way, the partial pressure of CO₂ is raised,        for example to 0.5 bar, and the cleaning becomes more efficient.        An essential disadvantage is that the partial pressure of oxygen        in the gas also becomes high, for example 1.5 bar, while amines        typically degrade quickly at oxygen partial pressures above        about 0.2 bar. In addition, costly extra equipment is required.        Other combinations of primary and secondary power stations        exist.    -   Air separation. By separating the air that goes into the        combustion installation into oxygen and nitrogen, circulating        CO₂ can be used as a propellant gas in a power plant. Without        nitrogen to dilute the CO₂ formed, the CO₂ in the exhaust gas        will have a relatively high partial pressure, approximately up        to 1 bar. Excess CO₂ from the combustion can then be separated        out relatively simply so that the installation for collection of        CO₂ can be simplified. However the total costs for such a system        becomes relatively high, as one must have a substantial plant        for production of oxygen in addition the power plant. Production        and combustion of pure oxygen represent considerable safety        challenges, in addition to great demands on the material. This        will also most likely require development of new turbines.    -   Conversion of the fuel. Hydrocarbon fuels are converted        (reformed) to hydrogen and CO₂ in pressurized processing units        called reformers. The product from the reformers contains CO₂        with a high partial pressure so that CO₂ can be separated out        and deposited or used in another way. Hydrogen is used as fuel.        The total plant becomes complicated and expensive, as it        comprises a hydrogen-generating plant and a power plant.

A common feature of the alternative methods for capture of CO₂ from apower plant is that they strive for a high partial pressure of CO₂ inthe processing units where the cleaning is carried out. In addition,alternative methods are characterized by long-term, expensive and riskydevelopments, with a typical time frame of 15 years research and afurther 5 to 10 years or more before operating experience is attained.Expected electrical efficiency is up to 56 to 58% for a plant withoutcleaning and probably, somewhat optimistically, 45 to 50% with cleaning.

An extended time frame is environmentally very undesirable. In a UnitedNations Economic Commission for Europe (UNECE) conference in the autumnof 2002, “an urgent need to address the continuing exponential rise inglobal CO₂ emissions” was emphasised and words such as “as soon aspossible” and “need to go far beyond Kyoto protocol targets” were used.

Thus there is a need for plants that overcome the mentioned problems,having the following characteristics:

-   -   Realizable without long-term development, preferably with the        use of rotary equipment that has already been tested out.    -   Adapted for a sufficient partial pressure of CO₂ so that        conventional absorption installations can be used effectively,        which means partial pressures up to 1.5 bara.    -   Lowest possible gas stream volume where CO₂ shall be captured,        relative to the power produced    -   Partial pressure of oxygen down to or preferably below 0.2 bara        where CO₂ shall be captured for thereby to minimize the        degradation of the absorption agent.    -   Possibility for effective cleaning of NOx, which is typically        carried out in the temperature range 300 to 400° C. Cleaning in        a pressurized system is optimal.    -   Efficiency in line with competing systems.    -   Possibility for large installations above 400 MW.    -   No use of reformers, processes for production of oxygen,        processes for conversion of the fuel or rotating equipment that        does not contribute to the net power output.    -   Compact and robust plant to benefit from the cost advantages by        building the plant at shipyards on floating constructions. This        also makes use at offshore installations possible.

According to a first aspect, the present invention relates to a methodfor separation of CO₂ from the combustion gas from a thermal power plantfired with fossil fuel, the method comprising the following steps;

a) cooling and mixing the combustion gas from the thermal power plantwith air;

b) compressing the combustion gas—air mixture;

c) reheating the compressed gas from step b) by using it as an oxygencontaining gas for combustion of natural gas in a pressurized combustionchamber to form an exhaust gas;

d) regulating the supply of natural gas and oxygen containing gas in thecombustion chamber so that the exhaust gas contains less than 6% restoxygen;

e) keeping the temperature in the exhaust gas between 700 and 900° C. bygeneration of steam in tubular coils in the combustion chamber;

f) cooling the the exhaust gas and bringing it in contact with anabsorbent absorbing CO₂ from the exhaust gas to form a low CO₂ streamand an absorbent with absorbed CO₂;

g) heating the low CO₂ stream by means of heat exchanges against the hotexhaust gas leaving the combustion chamber; and

h) expanding the heated low CO₂ stream in turbines.

The air added in step a) has two purposes. Firstly, the compressors instep b) requires a constant volume of incoming gas. Accordingly, the airhas a purpose as a “make up gas” to adjust the total volume of gasentering the compressors. Secondly, the oxygen in the air is used toincrease and regulate oxygen content in the pressurized combustionchamber to optimize the combustion.

The absorbent used in step f) with absorbed CO₂ is preferablyregenerated to form a CO₂ rich stream and regenerated absorbent.

The steam generated for cooling the combustion chamber in step e) ispreferably expanded in turbines to generate power.

According to a second aspect the present invention relates to aseparation plant for separation of the combustion gas from a thermalpower plant into a CO₂ poor stream and a CO₂ rich stream, the plantcomprising an air/combustion gas mixer, a combustion chamber for furthercombustion of the mixture of air and combustion gas from the powerplant, a supply line (9) for supply of hydrocarbon fuel to thecombustion chamber, means for cooling the exhaust gas from thecombustion chamber, a contact device for bringing the cooled exhaust gasin contact with an absorbent for absorption of CO₂ where a CO₂ poorstream, that is released into the atmosphere, is generated, aregeneration loop for regeneration of the absorbent and generation of aCO₂ rich stream, and an associated power plant producing power from theheat produced in the combustion chamber.

Preferably, the separation plant additionally comprises compressor(s)for compressing the combustion gas from the power plant and turbine(s)for expansion of the CO₂ poor stream before it is released into theatmosphere. It is preferred that the absorption takes place at anelevated pressure. The combustion gas from the power plant is thereforepreferably compressed before combustion in the combustion chamber of theseparation plant to ascertain that the heat of compression is not lost.

According to an embodiment, the plant also comprises heat exchangers forheating the CO₂ poor stream by heat exchanging against the exhaust gasfrom the combustion chamber before the CO₂ poor stream is expanded overturbine(s). Heating the exhaust gas increases the energy yield from theplant and thus reduces the heat loss in the system.

According to another embodiment, the plant additionally comprises linesfor transferring heat as hot water or steam between the power plant andthe separation plant.

According to a third aspect, the present invention relates to a combinedthermal power plant and separation plant for separation of thecombustion gas from the thermal power plant in a CO₂ rich and a CO₂ poorfraction, comprising a thermal power plant fired by carbon or ahydrocarbon and a separation plant for separation of the combustion gasfrom a thermal power plant into a CO₂ poor stream and a CO₂ rich stream,the plant comprising an air/combustion gas mixer, a combustion chamberfor further combustion of the mixture of air and combustion gas from thepower plant, a supply line (9) for supply of hydrocarbon fuel to thecombustion chamber, means for cooling the exhaust gas from thecombustion chamber, a contact device for bringing the cooled exhaust gasin contact with an absorbent for absorption of CO₂ where a CO₂ poorstream, that is released into the atmosphere, is generated, aregeneration loop for regeneration of the absorbent and generation of aCO₂ rich stream, and an associated power plant producing power from theheat produced in the combustion chamber.

Preferably, the power plant is fired by a hydrocarbon, preferably bynatural gas.

Preferably, the power plant is fired by a hydrocarbon, preferably bynatural gas.

The present invention will now be explained in more detail withreference to preferred embodiments and the enclosed figures, in which:

FIG. 1 is a simplified flow diagram that shows a basic embodiment of acombined plant for thermal power production and CO₂ removal forcombination with a thermal gas power plant;

FIG. 2 is a simplified flow diagram showing a gas power plant to becoupled with the plant according to FIG. 1;

FIG. 3 is a simplified flow diagram showing an alternative gas powerplant to be coupled with the plant according to FIG. 1;

FIG. 4 is a simplified flow diagram that shows a basic embodiment of acombined plant for thermal power production and CO₂ removal forcombination with a thermal coal power plant;

FIG. 5 is a simplified diagram showing a coal power plant to be coupledwith the plant according to FIG. 4;

FIG. 6 is a cross section through a mixing box used in the presentpurification works; and

FIG. 7 is a length section through the mixing box.

A basic configuration for a combined plant for thermal power productionand CO₂ removal, according to the present invention, is illustrated inFIG. 1, and will be described first

The combined plant for thermal power production and CO₂ removal receivesflue gas from a power plant, for example one of the power plantsillustrated in FIGS. 2,3 or 5 through a line 1. Three different powerplants 100 combined with the combined plant for thermal power productionand CO₂ removal are described in the following examples 1, 2 and 3.

The flue as from the power plant 100 comprises a mixture of oxygen, CO₂,H₂O and nitrogen. Typically, the flue gas from a thermal power plantbased on gas turbine(s) has a rest oxygen content of about 10 to 14 vol% depending on flue gas recirculation, whereas a coal based thermalpower plant wherein the combustion occurs in a combustion chamber has arest oxygen content of about 6 to 10 vol % or lower.

The flue gas from the power plant 100 is in the following descriptionand patent claims referred to as “flue gas”.

The flue gas enters the plant through line 1, optionally together withextra air to increase the oxygen content in the flue gas, and iscompressed in a compressor 2,2′. Air may be added to the flue gas fromthe power plant to give the compressor 2 optimum operating conditions,and/or to provide extra oxygen such that an optimum amount of heat canbe produced in combustion chamber 6. The compressor 2,2′ can be in onestage, but it is preferred that the compressor 2 is two or morecompressors in series, preferably with intermediate cooling of the airbetween the compressors 2 and 2′ as shown by a heat exchanger 45 thatcools the first exhaust gas in line 3′ between the two compressors. Twocompressors, 2,2′, as shown in FIG. 1, are preferred at the favoredworking pressure for the present invention which lies around 12 to 16bar. The incoming flue gas is compressed in the compressor 2′ to around4 bar. The flue gas is led from compressor 2′ to compressor 2 by way ofa line 3′. The flue gas in the line 3′ is cooled in a heat exchanger 45between the compressors before it is led into compressor 2. Incompressor 2 the flue gas is further compressed to a pressure of around12 bar.

From compressor 2 the compressed flue gas is split in two. Most of thecompressed flue gas is led by way of a line 3 to a combustion chamber 6.The rest, less than 10%, is bypassed the combustion chamber 6 throughline 7. The pressure of the flue gas is determined by the compressorcharacteristics, and drops slightly through combustion chamber 6, heatexchangers 8, 11, trim cooler 12 and purification unit 13. The totalpressure drop through this system to turbine 15 is in the order of 1 to2 bar. Much of this pressure drop occurs in the hot heat exchanger 8, inparticular if the temperature of stream 14A is above about 800° C. Heatexchanger 8, or the warmest part of heat exchanger 8 may therefore bereplaced by a not shown gas-fired afterburner in line 14A The gas-firedafterburner may be supplied with compressed flue gas from compressor 2as an oxygen containing gas.

Fuel containing carbon or carbon compounds, such as for examplehydrocarbons such as gas or oil, are fed to the combustion chamber 6through fuel supply 9. The fuel gas may be preheated before it isintroduced into the combustion chamber. The fuel gas may be preheated ina heat exchanger 80 against a part of the hot compressed flue gas takenout of the compressor 2. The cooled flue gas is thereafter led to otherpurposes through a line 7. The fuel gas may alternatively be heatedusing warm water from any available source.

Fuel that shall go into the combustion chamber 6 is pressurized by apump (not shown) or the like to a pressure that permits the fuel to beforced into the combustion chamber. Thus, the pressure here must lieabove the working pressure in the combustion chamber by, for example 0.5to 1 bar, such as 0.7 bar.

Use of burners that give a low NO_(x) content in the exhaust gas arepreferred due to the environmentally alarming aspects of releasing suchgases. With the use of such burners, NOx from a boiler with low NOxburners will typically be reduced to below 50 ppm. According to knownand tested technology, further NOx can be removed with NH₃ (3NO+2NH₃=2.5N₂+3H₂O) in a cleaning unit (not shown). This cleaning has up to 90%efficiency at atmospheric pressure, but is assumed to be much better atthe working pressure which is typically above 10 bara. It will thereforebe possible to clean NOx down to a residual content of 5 ppm or better.By adapting the heat exchangers, the gas can be given a temperature thatis optimal for this process. Other methods without NH₃ also exist. TheNH₃ method gives some NH₃ “slip”.

Downstream of the NO_(x) cleaning unit, it is possible to use a notshown scrubber that, by means of circulating water, saturates the gaswith water vapor and at the same time removes NH3 and other contaminantsfrom the exhaust gas. Downstream of this scrubber it is possible toemploy, in a not illustrated way, a cooling unit where the gas isbrought in contact with water. This causes water vapour from thecombustion process to condense. The water in the condensation unit istherefore heated. The warm water is used to re-heat and re-humidify thepurified gas in a humidification unit located downstream of the CO2absorption system, after the exit from absorption tower 13.

The combustion in the combustion chamber 6 occurs at a pressure fromatmospheric pressure to an overpressure, such as from 1.5 to 30 bar, forexample from 5 to 25 bar, such as from 10 to 20 bar. A pressure ofaround 12 to 16 bar has been found to be particularly preferred from thedemands of the subsequent cleaning and separation of CO₂ and operationexperience from gas turbines and air compressors. It is preferred with acombustion pressure of around 12 to 16 bar which is used in the examplepresented here.

The supply of oxygen-containing flue gas and optionally additional airand fuel is controlled such that the exhaust gas from the combustionchamber has a residual content of oxygen from 1 to 6% and morepreferably from 1-2%.

In the combustion chamber 6, water that is supplied through the watersupply 4, is heated in heating coils 21 to produce steam which is fedto, by way of a steam outlet 5, and expanded over a high pressureturbine 53. The expanded steam from the high pressure turbine 53 isthereafter led by way of a supply 4′ to the combustion chamber 6 to beheated up again in a another set of heating coils 21′. The re-heatedsteam leaves the combustion chamber in a line 5′ where it is led to amedium pressure turbine 54 where it is expanded.

From the steam turbine 54, the steam is led in a line 56 to alow-pressure turbine 57 where it is expanded further. The steam turbines53, 54 and the low-pressure turbine 57 are preferably arranged on acommon shaft 55 that drives a generator 58 for generation of electricenergy. For smaller systems, steam turbines 54 and 57 may be combinedinto a single unit.

Most of the expanded steam/condensed water is led from the low-pressureturbine 57 by way of a line 59 to a heat exchanger 60 which cools thewater further with external cooling water. After cooling/completecondensation, the water in line 59 is pumped up to the desired pressurefor further circulation with the aid of a pump 61. This relatively coldwater can be used to take care of low temperature energy at variouslocations in the plant in that it is heat exchanged with warmer streamswhich are to be cooled. This makes it possible to utilize/take care oflow temperature heat energy, something which is essential for goodenergy economics and also reduces the external cooling waterrequirements.

This is illustrated here by a heat exchanger 62 which heat exchanges thecold stream in line 59 with a warmer stream in line 63. The stream inline 63 is a stream which is taken from the low-pressure turbine at apoint where the steam is not completely expanded. The stream in line 63is again pumped up to desired pressure in the further circulation withthe aid of a pump 64. The streams in lines 59 and 63 are broughttogether in a line 65 which is heat exchanged with the exhaust gas fromthe combustion in an exhaust gas line 41, in a heat exchanger 67 to takecare of residual heat before the water is led into a combined water tankand deaerator 66.

A part stream of the cooled water in line 59 can be taken out in a line68 and heated up by heat exchange possibly initially with the partiallycooled exhaust gas in line 41 in a heat exchanger 69 and thereafter withthe hot air in line 3′ in a heat exchanger 45 before the water in line68 is led into the water tank 66. It is also possible to use water fromline 59 as cooling water for trim cooler 12 and for interstage coolingof compressor system 28.

From the water tank 66 the water is led by way of a line 70 to a pump 71where the water is pumped to a desired pressure. From the pump 71, thewater is led in line 70 to a heat exchanger 17 where the water is heatedup by heat exchange with the warm exhaust gas in line 41. It may bedesirable to take out smaller streams from the steam turbines 53 and 54in lines 72 and 73, respectively, and heat exchange these streams with aside stream of the stream in line 70, and use these for heating of thewater in heat exchangers 74 and 75. Heated water from the heatexchangers 17 and 74, respectively, is led into line 4 and in forcooling of the combustion chamber.

The gas in the combustion chamber 6 is cooled by this production ofsteam so that the working temperature in the combustion chamber is keptin the area 700 to 900° C., typically in the area 800 to 850° C.Preferably more than 50%, more preferred more than 60%, most preferredmore than 70% of the heat energy from the combustion in the combustionchamber is taken out as hot steam in the cooling of the combustionchamber.

The very large amount of heat which is removed from the combustionchamber ensures that most of the oxygen in the flue gas can be usedwithout the temperature becoming unacceptably high. This gives a highconcentration of CO₂ in the exhaust gas, consumption of relatively smallamounts of air in relation to the amount of energy which is produced,and thereby the essential advantage that a relatively small volumestream of exhaust gas will have to be cleaned. When most of the electricenergy is produced in efficient steam turbines, the heat load on thecritical gas-gas heat exchangers 8 and 11 is considerably reduced,something which gives reduced dimensions and simpler construction. Thelow temperature and reduced heat load also means that one has fewerproblems with heat expansion and corrosion than at higher temperatureand heat load. Plant costs and maintenance costs can thereby be reduced,at the same time as more energy is produced and cleaning of the exhaustgas is simplified without a great loss of electrical efficiency. Furtherenhancement may be accomplished by reducing the temperature in stream10A and instead replacing heat exchanger 8 or the warm inlet part ofheat exchanger 8 with an afterburner.

With reference to FIGS. 1 and 4, the exhaust gas from the combustionchamber 6 is led through an exhaust gas pipe 10, through one or moregas-gas heat exchangers 8, 11 and a trim cooler 12, where the exit gasis cooled before it is led into a contact device 13 where the gas isbrought into contact with an absorption agent. The pressure in thecontact device 13 lies close to the pressure in the combustion chamber 6as the pressure is only reduced corresponding to the drop in pressurethrough the heat exchangers 8, 11 and the trim cooler 12.

Water vapour, which is a result of the combustion in the combustionchamber 6 and which is condensed during the cooling of the exhaust gasthrough heat exchangers, is separated in a water separator 50 before thecontact device 13. Water can dilute and otherwise damage the absorptionagent in the contact device.

In the enclosed figure, heat exchangers 8, 11 are two heat exchangersthat are connected in series. The number of heat exchangers in seriesand or in parallel and the dimensioning of these are dependent on theactual dimensioning and design of an actual plant and can therefore varyfrom plant to plant. A typical plant will contain from two to four heatexchangers in series. The temperature in the contact device 13 isdependent on the absorption agent and is a compromise between lowtemperature which gives high solubility, and higher temperature whichpromotes reactions associated with the absorption process. Typicaltemperatures are below 20° C. for water, 40 to 60° C. for amines and 70to 100° C. for use of inorganic solutions, such as potassium carbonate.

The preferred absorption agents are fluids such as water, an amine oramino acid solution or an inorganic aqueous solution such as a carbonatesolution which can absorb relatively large amounts of CO₂ at highpressure and high partial pressure of CO₂. The absorption agent in thecontact device 13 preferably runs down a large inner surfacecounter-current to the gas. It should preferably have a low volatility,a high CO2 carrying capacity and a low sensitivity to oxygen.

The contact device is preferably operated at an elevated pressure, forexample above 8 bar, more preferably above 10 bar. The pressure can alsobe higher such as for example above 15 or 20 bar.

The gas from the exhaust gas which is not absorbed in the solvent is ledfrom the contact device through a gas pipe 14, through heat exchangers11, 8 where the gas is heated before it is expanded in turbine 15, 15′so that the energy is able to be used in the hot, high-pressure gasfurther on in the process. Entrained solvent from absorption column 13may be removed in a not shown scrubber in line 14B, and/or in a notshown gas re-humidification unit.

Water from the water separator 50 is preferably taken out through a line52, pumped by a pump 51 and led, together with the cleaned gas, intoline 14. The water is evaporated in the heating of the cleaned gas andsupplies the gas with a part of the mass, which has been removed in thecondensation of water and cleaning, and thus increases the heat capacityof the gas. The heat capacity and mass of gas in the line 14 ispreferably also increased by adding flue gas from line 7 as illustratedin FIGS. 1 and 4.

The efficiency can also be increased by inserting a compressor in line14, between the contact device 13 and heat exchangers 11, 8. Thiscompression heats the gas, a heat which can be taken out again later,and it makes it possible to permit a greater pressure drop in the heatexchangers. Thus, it is feasible to obtain a better heat transfer in asmaller area, something which makes it possible to use cheaper heatexchangers.

It can also be relevant to compensate for reduced mass flow because ofthe CO₂ which is removed, by feeding in a small compressed gas streamwhich is taken out of the ambient air, cool this gas down so that heatis not lost, for example by pre-heating some of the condensate fromcondenser 60, and lead this into the cleaned gas before the heatexchanger 11. It is preferred that the gas has about the sametemperature as the gas in line 14 and cooling should therefore be ratedaccording to this. A further alternative is to separate this air into anoxygen rich stream and an oxygen poor stream using for examplemembranes. The oxygen rich fraction is added to stream 1 and the oxygenpoor fraction is added to stream 14. The heat capacity and mass in line14 may also be increased by the addition of extra water obtained fromthe condensation of water vapour in line 41.

It is preferred that turbine 15 is more than one turbine, such as, forexample two turbines, 15 and 15′, connected in series, where a line 14′leads the gas which is partially expanded in turbine 15 to turbine 15′.

It can be preferable that compressor 2′ and turbine 15′ are arranged ona common shaft 40′ and that the compressor 2′ and the turbine 15′ arerated so that the kinetic energy from the turbine 15′ is just sufficientto drive the compressor 2′. Compressor 15 is arranged on a shaft 40together with compressor 2 and a generator 16. The kinetic energy fromturbine 15 is greater than what is required to drive the compressor 2and the remaining kinetic energy is therefore used to produceelectricity in a generator 16 which is placed on the same shaft. Thiskinetic energy can, if required, naturally also be used for otherpurposes, such as for example a re-circulation pump for the absorptionagent, a re circulation pump for boiler water, a vacuum pump, acompressor for the enriched CO₂, or a combination of these.

It is also possible that two or more compressor and turbine systems 2and 15 may be arranged in parallel.

From turbine 15, the expanded exit gas from the turbine 15 is ledthrough a heat exchanger 17 where the residual heat in the gas is usedfor a suitable application in the plant. In the embodiment shown, thisheat is used to heat the water in line 4.

In the shown device, the solvent containing CO₂ is fed from the contactdevice 13 by way of a pipe 19, by way of a heat exchanger 20 and anexpansion device (not shown) inside a desorption device 18. The pressurein the desorption device 18 is dependent on the choice of absorptionagent, the amount of absorbed CO₂ and the demands for regeneration. Thepressure will normally be lower than the pressure in the contact device13 and will normally be between 0.2 and 1 bar above the surroundingpressure.

To increase the release of absorbed gas from the absorbent in thedesorption device, a part of the absorbent will normally be removed inthe bottom of the desorption device and be led through a circulationpipe 44 through a circulation heater 22, where the absorbent is heatedbefore it is led back to the desorption device 18. Heat energy to thecirculation heater 22 can be taken out from another location in theplant, for example, in that a stream of steam is taken out, at asuitable pressure and temperature, from the low-temperature turbine 57and led in a line 76 to the heat exchanger 22 where the stream thecirculation pipe 44 is heated up by the hotter stream in line 76. Thesteam that has been taken out in line 76 is condensed in the heatexchanger and is pumped further to a water tank 66 by a pump 77. Forexample, 10 to 20 kg steam/s can be taken out in line 76 at atemperature of 200° C. and a pressure of 2.4 bar.

The energy requirement for this circulation heater is minimized as thecontact device 13 is driven at a high partial pressure of CO₂ in theincoming gas. At the same time, the steam which is used has a low valueas it is already partly expanded over high-pressure andintermediate-pressure turbines 53 and 54.

CO₂ rich gas which is released in the desorption device 18 is removedfrom the top of this and is then preferably led through a condenser 23,where it is cooled, and a liquid separator 24, before it is led througha CO₂ pipe 25 as a CO₂ rich gas stream. Liquid which is separated out inthe liquid separator 24 is returned to the desorption device through aliquid-carrying pipe 26.

Regenerated absorbent from the bottom of the desorption device 18 isremoved and pumped through a re-circulation pipe 43, cooled in a heatexchanger 20, and possibly further heat exchangers, before it isreturned to the absorption device 13.

The CO₂ rich gas stream from the liquid separator 24 is led to acompressor system 28 through a CO₂-carrying pipe 25, said compressorsystem comprises a number of compression steps in which the gas iscompressed in such a way that it can be stored, transported, depositedin a secure way or be sold. The components and construction of thiscompressor system are of a conventional type and will not be describedfurther here. This CO₂ rich gas stream will typically contain fromaround 80-95%, and preferably more than 90%, of the total CO₂ from theflue gas stream 1 and from the combustion chamber 6 according to thedesign and control parameters of the plant.

The gas which is led out in pipe 14 from the contact device 13 has a lowCO₂ content, typically around 10% of the total CO₂ from the flue gasstream 1 plus CO₂ produced in the combustion chamber 6. As mentionedabove, this gas is supplied with water that has previously been removedfrom the exhaust gas in water separator 50. This water is pumped by apump 51 through a line 52 into line 14 and the water and the gas in line14 are thereafter heated by heat exchange with the hot exhaust gas inheat exchangers 11 and 8 before it is expanded over the turbines 15,15′.

An essential feature of the present method and device is that asubstantial part of the heat energy from the combustion in thecombustion chamber 6 is taken out as steam which is used to drive thesteam turbines 53, 54 and 57. In that a substantial part of the heatenergy is taken out as steam, a feature which is much different fromconventional solutions, the temperature in the combustion chamber andconsequently of the exhaust gas from the combustion chamber is moderateand adapted to the operation of the gas turbine, and the combustionchamber pressure shell is further cooled, in spite of nearly fullutilization of the oxygen content of the air and thereby production of ahigh partial pressure of CO₂. This leads to considerably lower load andthereby demands on the heat exchanger 8, which would be a weak part in aplant where most of the heat energy is taken out in gas turbines drivenby the exhaust gas from the combustion. This is illustrated here bytable 1, which gives a few important measuring values for a plantaccording to the present invention.

EXAMPLE 1 CO₂ Removal from a One Stage Gas Power Plant

FIG. 2 illustrates a one stage thermal gas power plant 100. Natural gasis taken out from the gas inlet 9 (FIG. 1) and, after heating in heatexchanger 80, led to the power plant 100 in a line 81 and introducedinto a combustion chamber 105.

Air is introduced into the system through an air intake 101, compressedin a compressor 102 and led to the combustion through a line 103. Thecombustion gases from the combustion chamber 105 are led through a line106 to a gas turbine 107, where the gas is expanded. The combustionchamber 105 and line 106 are illustrated as separate units but isnormally integrated in the gas turbine 107. The compressor 102, the gasturbine 107 and a generator 109 for generation of electrical power arepreferably mounted on a common shaft 108.

The expanded combustion gas from the gas turbine 107 is led through aline 110 via heat exchangers illustrated by heat exchanger 111 and trimcooler 112 before the cooled combustion gas is introduced into a waterseparator 113. In the water separator, water produced as a result ofcombustion, is separated from the combustion gas and removed through aline 114. This water may be purified and used to increase the mass flowand heat capacity in line 14 on FIG. 1. The flue gas is then split intoa recirculation line 115, that is introduced into the air intake 101.The recirculation, which may be up to 40% of the total flow through theturbine, allows a higher mass flow through compressor and turbine system102 and 107, than through compressor 2 on FIG. 1. This allows the twosystems to work together, and increases the overall efficiency of thesystem. It is also possible, and may be preferred, to operate the systemwithout recirculation line 115. The flue gas is introduced into thecombined thermal power plant and CO₂ removal unit as described above andillustrated in FIG. 1. The flue gas leaving the water separator 113 hasa residual O₂ level of about 10 to 14 vol %. Preferably, air is addedinto the flue gas before it is introduced into the works illustrated inFIG. 1. The introduction of air including mixing of air and flue gas, ispreferably carried out in a mixing box 135. The mixing box is preferablydimensioned to allow a retention period, for example 10 seconds, toassure thorough mixing of the gases and smoothen out minor variations inpressure in the gas leaving the power plant. A typical mixing box hasthe shape of an upright cylinder and has a total volume of about 1000 m³for a 100 MW plant, and about 4000 m³ for a 400 MW plant.

FIGS. 6 and 7 illustrate a presently preferred embodiment of the mixingbox. The flue gas from the power plant enters into the mixing boxthrough an inlet 137 directing the incoming gas flow principallytangential to the circular walls of the mixing box close to the topthereof. The flue gas and air mixture leaves the mixing box in an outlet138 close to the bottom of the mixing box. From the outlet 138 the gasmixture is introduced to line 1 in FIG. 1.

Water formed by condensation in the mixing box is removed through awater outlet 142. To improve the mixing of flue gas and air, theincoming gas flow from the power plant may impel blades 139 insertedonto the mixing tank and having an axis of rotation that mainlycoincides with the length axis of the mixing tank. The blades areconnected to a screw forcing the flue gas and air downwards in themixing tank.

The mixing tank 135 has an at least partly open top allowing air to flowinto the tank. To avoid rain or other matters to fall into the tank, aroof 141 may be provided at the top of the tank.

Heat in the combustion gas leaving the gas turbine 107 is used to heatwater/produce steam for the steam turbines 53, 54 and/or 57 (FIG. 1). Apart of the water in line 59 (FIG. 1) is taken out in a line 83 andpumped by means of a pump 85 through a line 85 into a water tank 118.The water in the tank 118 is pumped by a pump 117 through a line 116 andheated in the heat exchanger 111 by cooling the combustion gas in line110. The hot water/steam leaving the heat exchanger 111 is led in a line82 and introduced into water supply line 4 (FIG. 1), or alternativelydirectly into a superheater in combustion chamber 6 (FIG. 1) and thenmixed with the high pressure steam 5. The heat exchanger 111 may consistof several heat exchangers in series, the hottest cooled by evaporationof water under high pressure, and the colder ones cooled by evaporationof water under lower pressures. The low pressure steam produced here maybe superheated in boiler 6 (FIG. 1) and or used directly in steamturbines 53, 54 or 57 (FIG. 1). This increases the utilization of heatin stream 110, without problems caused by temperature cross in the heatexchangers.

Table 1 gives typical pressures, temperatures, amounts and effects atdifferent locations in a power plant including a thermal gas power plantaccording to FIG. 2 and a combined thermal power plant and CO₂ removalunit according to FIG. 1. TABLE 1 Pressure, temperature, amount andeffect for different units/at different locations in a 100 MW plant.Pressure Temperature Amount Ref. no. (bar) (° C.) (kg/s) Effect (MW)  11.013 20 89  3′A 4 180 89  3′ 4 140 89  3 12 300 79  4 190 360 46  4′44.5 350 46  5 160 540 46  5′ 39 540 46  6 12  7 12 40 10  9A 33 260 2.6 10A 12 850 81.6  10C 78 81.6  14A 830 80.6  14B 65.6  16 13  25 11  41A1.013 400 80.6  41 85 80.6  50 12 70  52 5  56 10  58 66  59 0.03 24 40 59A 17  66 34 230  68A 90 10  68B 170 10  72 <0.5  73 <0.5  76 2.4 6 81 33 260 2.1  82 190 415 22  85 24 22 101 1.013 15 90 103 33 540 1051100-1200 106 33 1175 109 43 110 450 114 3Recirculation in line 115 in the example is 30% of the total combustiongas.

EXAMPLE 2 CO₂ Removal from a Two Stage Gas Power Plant

FIG. 3 illustrates a two stage thermal gas power plant. The elementscorresponding to the elements described in Example 1 and illustrated inFIG. 2 have the same reference numbers and are not described again hereunless regarded as necessary.

The flue gas leaving the first stage, corresponding to the thermal gaspower plant in FIG. 2, is split into a recirculation line 115, as inFIG. 2, and secondary air line 120. It is also possible to omitrecirculation line 115, and instead balance the flue gas rate from 113and the volume flow requirement in line 120 by means of a not shown airinlet mixing box similar to 135. The exhaust gas from the first stage inthe secondary air line 120 is introduced into the second stage,compressed in a compressor 121 and led to a combustion chamber 123through a line 122. Natural gas in line 81 is introduced through line81B as additional fuel into the combustion chamber 123.

The combustion gases from the combustion chamber 123 are led through aline 124 to a gas turbine 126, where the gas is expanded. The combustionchamber 123 and line 122 are illustrated as separate units but isnormally integrated in the gas turbine 126. The compressor 121, the gasturbine 126 and a generator 127 for generation of electrical power arepreferably mounted on a common shaft 125.

The expanded combustion gas from the gas turbine 126 is led through aline 128 via heat exchangers illustrated by heat exchanger 129 and trimcooler 130 before the cooled combustion gas is introduced into a waterseparator 131. In the water separator, water produced as a result ofcombustion, is separated from the combustion gas and removed through aline 132. The remaining flue gas is split into a recirculation line 133,and introduced into the air intake 120 and a flue gas line 1. Therecirculation, which may be up to 40% of the total flow through theturbine, allows a higher mass flow through turbine systems 107 and 126,than through compressor 2 on FIG. 1. This allows the two systems to worktogether, and increases the overall efficiency of the system. It is alsopossible to omit recirculation line 133. The flue gas in the flue gasline is introduced into the combined thermal power plant and CO₂ removalunit as described above and illustrated in FIG. 1. The flue gas has arest O₂ level of about 10 vol %.

Additional air may be added into the flue gas in a mixing box 135 asdescribed in Example 1, before the gas enters line 1.

Heat in the combustion gases leaving the gas turbines 107 and 126 areused to heat water/produce steam for the steam turbines 53, 54 and 57(FIG. 1). A part of the water in line 59 (FIG. 1) is taken out in a line83 and pumped by means of a pump 84 through a line 85 into a water tank118. The water in the tank 118 is pumped by a pump 117 through a line116, is split in two lines, one to the heat exchanger 111 in the firststage, and the other to the heat exchanger 129 in the second stage. Thewater is heated and steam produced in the heat exchangers 111 and 129 bycooling the combustion gases in lines 110 and 128, respectively. The hotwater/steam leaving the heat exchangers 111 and 129 is led in lines 82Aand 82B into line 82 and is introduced into water supply line 4 (FIG.1). Each of the heat exchangers 111 and 129 may consist of more than oneheat exchanger, for example three in series. The hottest of these arecooled by evaporation of water under high pressure, and the colder onescooled by evaporation of water under lower pressures. The low pressuresteam produced here may be superheated in boiler 6 (FIG. 1) and or useddirectly in steam turbines 53, 54 or 57 (FIG. 1). This increases theutilization of heat in stream 110 and 128, without causing problemsrelated to temperature cross in the heat exchangers.

Table 2 gives typical pressures, temperatures, amounts and effects atdifferent locations in a power plant including a thermal gas power plantaccording to FIG. 3 and a combined thermal power plant and CO₂ removalunit according to FIG. 1. TABLE 2 Pressure, temperature, amount andeffect for different units/at different locations in a 100 MW plant.Pressure Temperature Amount Ref. no. (bar) (° C.) (kg/s) Effect (MW)  11.013 20 88  3′A 4 180 88  3′ 4 140 88  3 12 300 78  4 190 360 48  4′ 39275 48  5 160 460 48  5′ 39 460 48  6 12  7 12 40 10  9A 33 260 2.3  10A12 850 80.3  10C 78 80.3  14A 830 79  14B 64.3  16 12.5  25 11.4  41A1.013 400 79  41 190 79  50 12 70  52 4.6  56 10  58 62  59 0.03 24 42 66 34 200  68A 69 7  68B 175 7  72 <0.5  73 <0.5  76 2.4 6  81 33 2602.8  81A 33 260 1.45  81B 33 260 1.35  82 190 380 31.4  82A 190 380 15 82B 190 380 16.4  85 24 31.4 101 1.013 15 90 103 33 540 90 1051100-1200 106 33 1155 109 29 110 435 114 1.8 120 1 20 89.65 122 33 89.65123 33 1100-1200 91 124 33 1113 91 127 26 128 1 420 91 132 1 20 2.8Recirculation of the total combustion gases in lines 115 and 133 is 0%in the example.

EXAMPLE 3 CO₂ removal from a thermal coal fired power plant

An exemplary plant is illustrated in FIGS. 4 and 5. FIG. 4 illustrates acombined thermal gas power plant and CO₂ removal unit, and FIG. 5illustrates a coal fired thermal power plant to be coupled with theplant at FIG. 4.

The plant according to FIG. 4 corresponds to the plant of FIG. 1 whereinlines 81, 82, 83, 85 and the pump 84 are removed and lines 87A and 87Band a heat exchanger 86 is inserted. The heat exchanger 86 heatsincoming water in line 87A and cools the exhaust gas in line 41. Theheated water leaves the heat exchanger in line 87B.

Carbon fuel is introduced from a coal line 150 into a combustion chamber149 wherein the coal is combusted by introduction of air from a air feedline 151. The air in the air feed line is preferably preheated by heatexchanging in a heat exchanger 152 against the hot combustion gasleaving the combustion chamber 149 in combustion line 153.

The combustion gases leaving the heat exchanger 152 are additionallycooled in a heat exchanger 154 and a trim cooler 155 before thecombustion gases are introduced into a scrubber 156 where the gas isscrubbed with water for removal of solids and dust. The scrubbed fluegas leaves the scrubber through a flue gas line 1 and introduced to theplant illustrated in FIG. 4. Additionally air is preferably introducedinto line 1 from an air feed line 164 to increase the percentage of O₂in the line 1. The flue gas in flue gas line 1 is used as oxygencontaining gas in line 1 in FIG. 4. Additionally, air may be added intothe flue gas in a mixing box 135 as described in Example 1.

Water for scrubbing of the flue gas is removed from the scrubber 156 ina line 157 together with the solids and dust removed from the gas,pumped by means of a pump 158 through a line 159 and filtered in afilter unit 161 before the water is reintroduced into the scrubberthrough a line 162. Surplus water, resulting from the combustion in thecombustion chamber, is removed from the recirculation in a line 160.

The combustion chamber is cooled down by production of hot water andsteam in heating coils 165, 166 in the combustion chamber. Water forproduction of hot water and steam is taken out from a water tank 177though a line 178, pumped by a pump 179 via heat exchangers 174, 176 andled by means of a line 167 to the first heating coil 166 where steam isproduced.

Steam leaving the heat coil 166 through a line 168 is expanded in asteam turbine 171. The expanded steam is returned through a line 169 tothe second heat coil 165 inside the combustion chamber 149 where it isreheated. The reheated steam leaves the heating coil 165 in a line 170leading the steam to a second steam turbine 172 where the steam isexpanded again. The expanded steam from steam turbine 172 is led througha line 183 to a steam turbine 181 where the steam is expanded further.

A minor part of the steam from the steam turbine 172 is led through aline 188 directly into the water tank 177 to give the correct massbalance in the system. The amount is sufficient to keep the temperatureat the boiling point, plus a small extra flow to remove volatile gasesfrom the boiler water, although such extra flow is not shown in Tables1, 2 or 3.

The steam turbines 171, 172 and 181 are preferably mounted on a commonshaft 180 that are powering a generator 182 for generation ofelectricity. Fully expanded steam/water is withdrawn from the turbine181 through a line 184, whereas some partly expanded water/steam iswithdrawn from the turbine in a line 189.

The water vapor in line 184 is condensed in a heat exchanger 185receiving cooling water from a suitable source. The condensate is thenpumped by means of a pump 186 and heated in a heat exchanger 187 againstthe partly expanded steam/water in line 189. The partly heated water isthereafter heated further in heat exchanger 154, where it is heatexchanged against the partly cooled combustion gas in line 153 before itis led in a line 87 A to the heat exchanger 86 (FIG. 4). The hotwater/steam withdrawn from the turbine 181 in line 189 is pumped bymeans of a pump 190 into line 87A after leaving the heat exchanger 187.

The water in line 87A that has been heated in heat exchanger 86 isreturned into the water tank in line 87B.

Heat exchanges 174 and 176 receive steam from turbine 171 via a line173, respectively turbine 172 via line 175. The steam in lines 173 and175 is after cooling and condensation in the heat exchangers 174 and 176led to the water tank 177.

Table 3 gives typical pressures, temperatures, amounts and effects atdifferent locations in a power plant including a thermal coal powerplant according to FIG. 5 and a combined thermal power plant and CO₂removal unit according to FIG. 4. TABLE 3 Pressure, temperature, amountand effect for different units/at different locations in a 100 MW plant.Pressure Temperature Amount Composition Ref. no. (bar) (° C.) (kg/s)Effect (MW) vol %  1 1.013 20 91  12 (O₂)  5 (CO₂)  3 12 300 83  4 190315 27  4′ 45 330 26  5 180 540 27  5′ 39 540 26  7 12 8  9 12 15 2.5 10A 12 870 85  14A 11 845 82  14B 11.5 70 68  16 13  25 11.3 100 (CO₂) 41 About 1 84 82  41A About 1 410 82  52 5  56 10 25.8  58 33  59 0.0325 13.2  63 0.2 0.6  66 25 175  68A 25 58 13.8  68B 25 135 13.8  70A 1904  70B 190 23  72 45 330 1  73 0.2  76 2 205 12  87A 20 75 33  87B 20135 33 151 1 15 60 151A 1 370 60 160 4 163 1 30 59  8 (O₂)  10 (CO₂) 1641 15 32  21 (O₂) 167 190 215 38 168 160 540 38 169 44.5 350 37 170 39540 37 173 44.5 350 1 175 1 177 20 175 182 55 183 10 350 33 184 0.03 2532.5 184A 33 32.5 188 3 189 60 0.5

The configuration according to the figures and the described embodimentsaccording to the present invention can be varied with respect to heatexchangers, pumps, etc, without this diverting from the inventiveconcept. Elements that are shown here with a symbol can be a combinationof similar or different elements which together give the desired anddescribed function. Thus, what has been illustrated as a heat exchangercan describe a combination of heat exchangers. Likewise, such a plantwill be able to encompass further elements which are not described here,such as further heat exchangers to take care of smaller amounts ofenergy, pumps or pressure reducing valves to regulate the pressure incertain elements, etc.

Similarly, during the engineering and optimization of a particularplant, one will be able to deviate from details in the described massand energy flow.

Line 7 can alternatively be supplied with air directly from thecompressors 2, 2′ or from a separate compressor (not shown).

A high-temperature heat exchanger should not be cooled down and heatedup repeatedly if it shall also function as a pressure container.Therefore, it can be advantageous that hot heat exchangers, i.e. theheat exchangers in which one of the streams is above 350° C., isconstructed with an outer pressure-shell and an inner shell betweenwhich flows a cooling medium, such as CO₂ or nitrogen, in the same wayas for the combustion chamber. Alternatively, the container around theheat exchanger can be cooled directly or indirectly with boiler water asthe cooling agent. A further alternative is to build the heat exchangerinside the pressurized combustion chamber, where it does not need tofunction as a pressure container any longer. It will also be possible toeliminate the hot heat exchanger, and instead achieve the requiredtemperature by using a small combustion chamber immediately upstream ofthe expansion turbine.

It can also be relevant to carry out other specific constructionadjustments on some elements, in particular to improve operating safety,reduce building costs and reduce the danger of wear and associatederrors. Thus, it can be relevant to use a cooling gas such as CO₂ tocool the shell of the combustion chamber 6 and other hot elements suchas hot heat exchangers, for example heat exchanger 8. This heat energyin this cooling gas can be used in that it is supplied to heatexchangers for heating at locations in the process where it is possibleto utilize low-grade energy, in particular this concerns preheating ofwater to the combustion chamber. Cooling of pressurized combustionchamber and pressurized heat exchangers to a shell temperature lowerthan 350° C. gives the opportunity of using high tensile, low-alloy andinexpensive steel qualities. The system can also be used for heating ofthese elements before start-up of the plant. This reduces heat tensionsand reduces the risk of cracking in pressure-shells and pipes.

It can furthermore be relevant to modify the cooling and condensationsystem between the combustion chamber and the CO₂ absorption unit topurify the gas with respect to NOx, SOx (sulfur compounds), heavyhydrocarbons that have not been oxidized in the combustion process andsolid particles. Such purification is typically carried out in scrubbingunits with circulating liquid such as water. Liquid supply, such aswater from downstream cooling and condensation processes, saturates thegas and assures that the liquid is not removed by vaporization. A sidestream from the circulating liquid carries the contaminants away fromthe process.

Downstream of the purification system the gas is cooled and water vaporcondenses. Heat is removed by vaporization of water in the purified gas,and possibly by using a cooling agent such as external cooling water.Such heat exchange with phase change gives particular problems withrespect to temperature differences between the hot and the cold side ofthe exchanger (pinch problems). It may be relevant to use specialdesigns for this condensation and re-humidification process, such as asingle container containing the heat exchangers. This will allowcirculating water in the CO₂ rich gas stream where condensation occurswhile at the same time removing heat. It will also allow circulatingwater in the CO₂ lean (purified) gas where vaporization orre-humidification occurs while at the same time adding heat. Circulatingwater improves the efficiency when water is condensed from the exhaustgas during cooling, or when water is vaporized into the purified exhaustgas that is being heated.

In addition, it may be relevant to use a scrubber with circulatingliquid such as water in the gas stream immediately downstream of the CO₂absorption column. This removes CO₂ absorbing chemicals to a very lowresidual level, preventing the escape of such chemicals to theatmosphere via the gas turbine system.

It may be relevant to increase the mass flow through the gas turbines byadding extra water to the exhaust gas downstream of the CO₂ absorptioncolumn. This water may be obtained from the expanded exhaust gasdownstream of the gas turbines, after the cooling and heat recovery fromthis gas. The water is obtained by further cooling and condensation ofwater vapor in the gas. This may be accomplished in a scrubber withcirculating water. Surplus heat is removed by external cooling of thecirculating water using a suitable cooling agent.

1. A method for separation of CO₂ from the combustion gas from a thermalpower plant fired with fossil fuel, the method comprising the followingsteps; a) cooling and mixing the combustion gas from the thermal powerplant with air; b) compressing the combustion gas—air mixture; c)reheating the compressed gas from step b) by using it as an oxygencontaining gas for combustion of natural gas in a pressurized combustionchamber to form an exhaust gas; d) regulating the supply of natural gasand oxygen containing gas in the combustion chamber so that the exhaustgas contains less than 6% rest oxygen; e) keeping the temperature in theexhaust gas between 700 and 900° C. by generation of steam in tubularcoils in the combustion chamber; f) cooling the the exhaust gas andbringing it in contact with an absorbent absorbing CO₂ from the exhaustgas to form a low CO₂ stream and an absorbent with absorbed CO₂; g)heating the low CO₂ stream by means of heat exchanges against the hotexhaust gas leaving the combustion chamber; and h) expanding the heatedlow CO₂ stream in turbines.
 2. The method according to claim 1, whereinthe absorbent used in step f) with absorbed CO₂ is regenerated to form aCO₂ rich stream and regenerated absorbent.
 3. The method of claim 1,wherein the steam generated for cooling the pressurized combustionchamber in step e) is expanded in turbines to generate power.
 4. Aseparation plant for separation of the combustion gas from a thermalpower plant (100) into a CO₂ poor stream and a CO₂ rich stream, theplant comprising an air/combustion gas mixer, a combustion chamber (6)for further combustion of the mixture of air and combustion gas from thepower plant (100), a supply line (9) for supply of hydrocarbon fuel tothe combustion chamber (6), means for cooling the exhaust gas from thecombustion chamber (6), a contact device (13) for bringing the cooledexhaust gas in contact with an absorbent for absorption of CO₂ where aCO₂ poor stream, that is released into the atmosphere, is generated, aregeneration loop (19, 18, 43, 20) for regeneration of the absorbent andgeneration of a CO₂ rich stream, and an associated power plant producingpower from the heat produced in the combustion chamber (6).
 5. Plantaccording to claim 4, additionally compressor(s) (2, 2′) for compressingthe combustion gas from the power plant (100) and turbine(s) (15, 15′)for expansion of the CO₂ poor stream before it is released into theatmosphere.
 6. Plant according to claim 4, additionally comprising heatexchangers (118) for heating the CO₂ poor stream by heat exchangingagainst the exhaust gas from the combustion chamber (6) before the CO₂poor stream is expanded over turbine(s) (15, 15′).
 7. Plant according toclaim 4, additionally comprising lines (82, 83, 85, 87) for transferringheat as hot water or steam between the power plant and the separationplant.
 8. A combined thermal power plant and separation plant forseparation of the combustion gas from the thermal power plant in a CO₂rich and a CO₂ poor fraction, comprising a thermal power plant fired bycarbon or a hydrocarbon and a separation plant according to claim
 5. 9.A combined plant according to claim 8, wherein the power plant is firedby a hydrocarbon, preferably by natural gas.
 10. The method of claim 2,wherein the steam generated for cooling the pressurized combustionchamber in step e) is expanded in turbines to generate power.
 11. Plantaccording to claim 5, additionally comprising lines (82, 83, 85, 87) fortransferring heat as hot water or steam between the power plant and theseparation plant.
 12. Plant according to claim 6, additionallycomprising lines (82, 83, 85, 87) for transferring heat as hot water orsteam between the power plant and the separation plant.